The invention is designed to work cooperatively with commonly utilized components of drilling assemblies. Components commonly in use in the drilling assembly are selected for specific properties. Drill collars, for example, are selected for their ability to convey weight and torque to the bit. Accordingly, they are torsionally rigid, relatively inflexible and are able to be run in compression without detriment. Drill-pipe, by comparison, is less torsionally rigid and has a much lower weight per unit length and is designed to be used in tension. In areas where high levels of drillstring vibration are encountered drillstring component failure is frequently found in the environs of the intersection of drill-collars and drill-pipe.
Acknowledging the problematic nature of the interface between drill collars and drill pipe, heavy wall drill pipe, a hybrid drillstring component, sharing properties of both drill-pipe and drill collars is frequently run as an interface between the drill-collar and drill-pipe elements with the objective of minimizing drillstring failure.
The instant device seeking to improve upon prior art, acts to isolate both drill collar and drill-pipe elements from unwanted harmonics and coupled in the 3 axis of axial, torsional and lateral vibration. These can lead to both torsional and rotational speed variations, phenomena often and collectively referred to in the industry as Slip-Stick.
It is preferably located in the drill-collar element of the drilling assembly and may, additionally, be preferentially equipped with stabilization. Multiple instances of the device may be run in series within a single drilling assembly.
The variables in the drilling process are numerous and while there are some constants, other variables are region specific. The different regions of the Earth where hydrocarbon exploration and development take place yield vastly different geological scenarios resulting in a wide variety of drilling conditions which downhole equipment must survive in order to be functionally and economically beneficial to the drilling process. Geology, formation structures, formation fluid pressures, wellbore tortuosity, wellbore trajectory, drilling fluid type, bit type, bottom-hole-assembly stabilization and casing programs, all play a part in affecting the components of the drilling assembly and the bottom-hole-assembly in particular.
A sequential examination of the drilling process is effective in illustrating the improvements which are proposed by the instant device.
At the commencement of the drilling operation, the drillstring is rotated and lowered into the wellbore until the bit contacts the rock formation. Weight is gradually applied and adjustments to the rotary speed are made until drilling commences.
It is worth noting that the driller, at surface adjusts rotary speed, not rotary torque: thus drilling proceeds with applied constant speed at surface and, not a constant torque. Constant torque would result in lower fluctuations in drill-pipe tortuosity and is at present practically only achieved through utilizing a positive displacement motor (PDM). PDMs represent a form of Moineaux screw assembly, with internal rotor and external stator. Widely used for directional and performance drilling purposes PDMs reduce bit generated stick-slip as the rotor to stator interaction acts as a de-coupler between the torsionally rigid collars and the bit. Recently, high-torque output motors have removed some of this damping effect, until, in terms of stick-slip, in many locations, there is little visible difference between drilling with a positive-displacement-motor and conventional rotary drilling.
A further difficulty is that measured weight on bit is effectively “surface” weight on bit, rather than downhole weight on bit. With the drillstring rotating, effectively nullifying wellbore frictional effects, the surface weight indicator is “zeroed” immediately prior to placing the bit on the bottom of the hole. The difference between the off-bottom suspended weight of the rotating drillstring and the weight of the drillstring during drilling is taken as the effective weight-on-bit.
The cutting action at the rock face depends on the type of bit employed and the parameters which are selected. Interaction with the formation is rendered more complex through geological considerations and the angle of intersection between bit and specific strata of the rock formation. Frictional characteristics between the bit and the rock formation are continually changing: this is especially true for PDC bits which cut the rock by shear-failure mode. Drillstring torque input is also continuously altering as a result of the changing friction and cutting loads within the wellbore. Particularly when drilling with PDC bits this manifests itself as a sinusoidal torque input to the surface motive means.
In the field of rotary drilling the drillstring, obeying Hooke's Law, is perceived to act as a spring. The lower component of the drillstring, often referred to as the Bottom Hole Assembly and consisting of Drill Collars, however, reacts differently to the drillpipe section of the drillstring as it has a very high torsional stiffness.
As a result of having these two major elements incorporated into the drillstring and adding bit generated friction and drill collar torsional resonance the drillstring undergoes harmonic oscillations which, at best, represent inefficiencies in the drilling process and at worst can cause drillstring failure with the added expense and unpredictability of remedial work. These oscillations can cause extremely large variations in rotational speeds at the drill bit whilst the input speed at surface can remain reasonably constant.
Depending on the characteristics of the wellbore, drillpipe, BHA and drill-bit, the torsion may result in perceived reduction in weight on bit, prior to the point of formation failure. This, then, results in additional drillpipe being “released” with the result that the weight on bit oscillates and traps additional torsion in the drillstring.
Adjustment of the at-bit axial feed-rate and compensation for harmonic oscillations in the length of the drillstring is one of the objects of the instant invention.
In summary, it should be stated that the number of sources and interactive characteristics of downhole harmonic vibration have, to date, eluded a generic solution which the instant device seeks to provide.
Background Art
The instant device, therefore, seeks to provide a preventive solution for one of the more destructive elements of the drilling process which occurs in a wide variety of rotary drilling scenarios and with varying degrees of severity. This element, at its most extreme, is often referred to as “stick-slip.”
Lesser magnitude events which do not qualify for the label “stick-slip” are more precisely identified as, among others, axial, lateral and torsional harmonics. In the environs of the bit and the bottom-hole-assembly some or all of the following characteristics may be present: drag, stick-slip—which at a maximum may cause the BHA to spin backwards, torque shocks (torsional vibration), drill-collar and bit whirl, drillpipe buckling, bit-bounce (axial shock loading of the BHA components) and lateral vibration. Warren and Oster in “Improved ROP in Hard and Abrasive Formations, Amoco Drilling Technology DTP 1453, 22 Dec., 1997 comment that once whirl begins it is self-sustaining as the centrifugal force maintains the effect and that stopping rotation is the only effective way to stop whirl. Generally speaking, “stick-slip” represents an extreme of the condition generically referred to as “drilling vibration” or “harmonic vibration.”
Any of these conditions results in a sub-optimal drilling process, with the magnitude of the condition being proportional to the reduction in drilling efficiency.
A definition of destructive vibration is required and perhaps the best single definition of stick-slip is given by John Dominick who provides a succinct description of the anomalies of drillstring behaviour in his U.S. patent [U.S. Pat. No. 6,065,332] “METHOD AND APPARATUS FOR SENSING AND DISPLAYING TORSIONAL VIBRATION.”
“During drilling operations, a drillstring is subjected to axial, lateral and torsional loads stemming from a variety of sources. In the context of a rotating drill string, torsional loads are imparted to the drill string by the rotary table, which rotates the drill string, and by the interference between the drill string and the wellbore. Axial loads act on the drill string as a result of the successive impacts of the drill bit on the cutting face, and as a result of irregular vertical feed rate of the drill string by the driller. The result of this multitude of forces applied to the drill string is a plurality of vibrations introduced into the drill string. The particular mode of vibration will depend on the type of load applied. For example, variations in the torque applied to the drill string will result in a torsional vibration in the drill string.
At the surface, torsional vibration in the drill string appears as a regular, periodic cycling of the rotary table torque. The torsional oscillations usually occur at a frequency that is close to a fundamental torsional mode of the drill string, which depends primarily on drill pipe length and size and the mass of the bottom hole assembly (BHA). The amplitude of the torsional vibrations depends upon the nature of the frictional torque applied to the drill string downhole, as well as the properties of the rotary table. Torsional vibrations propagating in the drill string are significant in that they are ordinarily accompanied by acceleration and deceleration of the BHA and bit, as well as repeated twisting of the drill pipe section of the drill string.”
The magnitude of these torsional characteristics is proportional to the reduction in efficiency in the drilling process: thus, removal or reduction of these destructive elements would, naturally, constitute an improvement to drilling efficiency. The invention proposes removal or reduction of “stick-slip” and, as a result, consequential improvements in drilling performance.
Grosso, (SPE 16,660, September, 1987) concluded; “Downhole measurements of forces and accelerations within the BHA have shown that the vibrations at the bit have large quasi-random components for axial and rotational movements . . . probably due to unevenness of formation strength, random breakage of rock and amplification of these effects by mode coupling . . . .” Grosso also concluded in (U.S. Pat. No. 4,878,206) METHOD AND APPARATUS FOR FILTERING NOISE FROM DATA SIGNALS, that stick-slip action was a combination of torsional and axial movements and that torsional and axial stick-slip measurement should be considered separately. An inventive step which the instant device proposes is to deal with torsional and axial stick-slip simultaneously.
Prior art in the domain of vibration measurement and control is plentiful, yet, to date, there has been little success in creating a panacea for stick-slip or success in diminishing drillstring harmonics and thereby deriving improvements to the drilling process.
The major sources of harmonic vibration have been identified as the rotary drive system above the rotary table, the drillstring, the torsionally rigid element of the BHA component of the drillstring and the bit to formation interaction. Each has an almost continuously varying degree of influence in the total system vibration and adding further complexity, each has an interactive effect on the other. Thus variations in bit generated torque will reflect in drillstring torque which feeds back into the rotary drive system: the system is complex, iterative and chaotically changing.
Prior art in the domain of drillstring vibration damping largely reflects two schools of thought.
The first approach asserts that stick-slip can be diminished through more precise control over the surface drive mechanism. As this represents the variable means of torque input into the drilling system, the premise of this group of industry studies and intellectual property is that by oscillating the drillstring at surface proportionally and synchronously to the observed harmonic frequency of the drilling assembly and in particular the drillstring, that drillstring downhole torque can be controlled and harmonic vibrations and in particular stick-slip reduced to within acceptable limits. Practical applications of this theory have proved effective in some but not all situations.
Worrall, (U.S. Pat. No. 5,117,926) METHOD AND SYSTEM FOR CONTROLLING VIBRATIONS IN BOREHOLE EQUIPMENT provided for control of the energy flow through the borehole equipment by defining “across” and “through” variables “wherein fluctuations in one variable are measured and the energy flow is controlled by adjusting the other variable in response to the measured fluctuations in said one variable.”
Van Den Steen (U.S. Pat. No. 6,166,654) DRILLING ASSEMBLY WITH REDUCED STICK-SLIP TENDENCY acknowledging the influence of topdrive and above rotary table harmonics proposes the addition of surface mounted torsional viscous damper sub-systems to the drilling assembly with the aim of introducing a lower rotational resonant frequency into the drilling assembly by negating harmonic influences induced by the rotating equipment located above the rotary table.
Keultjes et al (U.S. Pat. No. 6,327,539) METHOD OF DETERMINING DRILL STRING STIFFNESS proposes the determination of the rotational stiffness of a drill string and in particular determining the moment of inertia of the BHA for optimizing energy within the drilling assembly so as to reduce stick-slip effects.
The second school of thought asserts that downhole measurements and associated downhole mechanisms are the preferred route to controlling stick-slip in the bottom-hole assembly.
Prior Downhole Art
The Prior art in the domain of passive mechanical damping devices for rotary drilling has been deployed for over half a century. Generically such devices are referred to as “shock-subs”. Typically these devices have a splined, telescopic shaft axially co-located within a hollow cylindrical housing. When subjected to axial shock these devices perform a controlled telescopic translation along the principle axis of the borehole until the entirety of the shock has been absorbed. Internal damping mechanisms vary, but are predominantly Belleville spring, fluid compression, ring spring or gas charged. These devices have some degree of effectiveness, but are constrained by having their own internal natural frequency, which, at some stage will compound the existing wellbore harmonic. Additionally, shock subs are, largely, incompatible with directional drilling processes, directional wells and also relatively ineffective when dealing with high magnitude harmonic vibrations.
These devices also have inherent natural frequencies of their own which are not field tuneable to provide wider ranges of damping capability. In summary, they individually provide a single solution which attempts to suit the entire range of harmonic vibration conditions. The instant device constitutes an improvement over prior art in that it has no inherent natural frequency, or, alternatively that it has a natural frequency which is adjustable in the distal environment.
Prior downhole art can be further sub-divided into vibration measurement and vibration damping devices.
Early prior art in the field of downhole measurement focussed on the measurement of vibrations in the bottom-hole assembly, with the objective of quantifying accelerational characteristics with the ultimate objective of avoiding critical RPM bands. Downhole sampling and processor speeds in earlier devices precluded analysis across the wider range of harmonics.
Mason, (U.S. Pat. No. 5,448,911) METHOD AND APPARATUS FOR DETECTING IMPENDING STICKING OF A DRILLSTRING utilized a comparative method which identified impeding downhole sticking conditions and compared them to observed surface conditions. The objective of this invention was to identify surface condition parameters which were to be avoided.
Wassell (U.S. Pat. No. 5,226,332) VIBRATION MONITORING SYSTEM FOR DRILLSTRING proposed an alternate configuration for downhole sensors which allowed for enhanced accuracy in measurement of lateral and torsional vibration, once again with the objective of avoiding specific surface condition input parameters.
Pavone (U.S. Pat. No. 5,721,376) METHOD AND SYSTEM FOR PREDICTING THE APPEARANCE OF A DYSFUNCTION DURING DRILLING, focused on the creation of a drilling model constructed from measurements taken from sensors located in the drillstring.
As an alternative to measurement and avoidance of critical vibration across the entire frequency spectrum, prior art corrective procedures have generally focussed on the practical measures of predicting and avoiding critical rotary speeds. SPE Publication, 16675-MS “CASE STUDIES OF BHA VIBRATION FAILURE” by R. F. Mitchell and M. B. Allen, September, 1987 included the following commentary:
“Speeds that might result in destructive lateral vibrations are addressed with equations 9.11 and 9.12 of API RP 7G. A recent study has shown that these equations, even when modified to account for fluid added mass and precessional forces, do not accurately predict critical rotating speeds and do not correspond well with field experience.”
By 1990 the aforementioned formulae had been removed from API RP7G, which publication added as a comment:
“Numerous field cases have indicated that previous formulations given in Section 9.1 of API RP 7G, 12th Edition (May 1, 1987) did not accurately predict critical rotary speeds and thus have been removed. Presently no generally accepted method exists to accurately predict critical rotary speeds.”
Later art in the field of vibration damping through application of downhole assemblies and mechanisms has focussed on intelligent networks and processes which integrate sensor inputs with logic control either encompassed within a downhole device or, alternatively transferred back to surface in order for the operator to make corrective actions.
Accurate measurements of acceleration and vibration are encoded and conveyed back to the surface of the earth using any of a variety of commercially available telemetry methods or, alternatively, recorded in the downhole environment and reserved for post-well analysis. These measurements are then reconstructed to quantify downhole harmonic vibration.
At surface “BHA Modelling” may take place. BHA modelling, largely using finite-element analysis techniques, seeks to avoid specific resonant vibrations which are incompatible with a particular BHA, drill bit and rock formation configuration. However, Jogi (U.S. Pat. No. 6,205,851) METHOD FOR DETERMINING DRILL COLLAR WHIRL IN A BHA AND METHOD FOR DETERMINING BOREHOLE SIZE identified the inherent weaknesses in these modelling efforts, noting that even slight variations in hole enlargement or in drill-collar concentricity caused by bends within the drill-collar, or drill-collar “sag”, curvature of the borehole or BHA imbalances reduces pre-well BHA modelling effectiveness as it alters the natural frequency of the BHA. Unfortunately these variations are unquantifiable until the well is in progress.
Research has shown that the main causes of premature bit and BHA damage in any one drilling scenario are, largely, confined to one or two major frequencies with single “sidebands”. The abstract of MacPherson (U.S. Pat. No. 5,321,981) “METHODS FOR ANALYSIS OF DRILLSTRING VIBRATION USING TORSIONALLY INDUCED FREQUENCY MODULATION” informs:
“Torsional oscillations of the drillstring will lead to frequency modulation (FM) of the signal from a vibratory source (e.g. the bit). This results in the frequency domain, in sidebands being present around a detected excitation frequency. In accordance with the present invention, it has been discovered that these sidebands may be used in advantageous methods for optimizing drillstring and drilling performance. In a first embodiment of this invention, these sidebands are used to discriminate between downhole and surface vibrational sources.”
Dubinsky et al (U.S. Pat. No. 6,021,377) DRILLING SYSTEM UTILIZING DOWNHOLE DYSFUNCTIONS FOR DETERMINING CORRECTIVE ACTIONS AND SIMULATING DRILLING CONDITIONS, provides for a “closed-loop” system where downhole dysfunctions are quantified by sensors and the results telemetered to surface where a surface control unit determines the severity of dysfunction and the operator provides corrective action which is required to alleviate the dysfunction at surface.
MacDonald et al (U.S. Pat. No. 6,732,052) METHOD AND APPARATUS FOR PREDICTION CONTROL IN DRILLING DYNAMICS USING NEURAL NETWORKS proposes:
“a drilling system that utilizes a neural network for predictive control of drilling operations. A downhole processor controls the operation of devices in a bottom hole assembly to effect changes to drilling parameters [and drilling direction] to autonomously optimize the drilling effectiveness. The neural network iteratively updates a prediction model of the drilling operations and provides recommendations for drilling corrections to a drilling operator.”
This approach has achieved some recent success; however, its objective is the avoidance of BHA/well specific destructive RPM ranges through operator intervention at surface. Using these methods may reduce harmonic vibration, yet compromise rate of penetration as a result of the selection of sub-optimal drilling RPM ranges. Once destructive harmonics have been identified, they are avoided, rather than negated.
Prior art, therefore indicates that downhole measurements of whatever degree of sophistication are utilized as means for avoidance of detrimental harmonics.
Downhole Vibration Tools
Forrest (U.S. Pat. No. 4,901,806) APPARATUS FOR CONTROLLED ABSORBTION OF AXIAL AND TORSIONAL FORCES IN A WELL STRING proposed the use of a modified positive displacement motor with hydraulic choke means as a method for damping vibrations. The rotor stator interaction is utilized as a torque retractor with additional spring loading. The Forrest device is non instrumented and non-adaptive. The instant device claims improvement in that irrespective of alterations to the downhole environment it is configurable to deliver constant weight and torque via the BHA to the bit face without compromising drilling parameters.
More recently, Gleitman et al (U.S. Pat. No. 7,204,324) ROTATING SYSTEMS ASSOCIATED WITH DRILL PIPE and (U.S. Pat. No. 7,219,747) PROVIDING A LOCAL RESPONSE TO A LOCAL CONDITION IN AN OIL WELL provides for a “controllable element (which) is provided to modulate energy in the drillstring. A controller is coupled to the sensor and to the controllable element. The controller receives a signal from the sensor, the signal indicating the presence of said local condition, processes the signal to determine a local energy modulation in the drill string to modify said local condition, and sends a signal to the controllable element to cause the local determined local energy modulation.”
Gleitman further proposes the use of sensors to measure parameters such as strain, pressure, temperature, force, rotation, translation, accelerometers, shock, borehole proximity and calipers. Deployed at various intervals of the drillstring and acting on output from the sensors a series of individual devices are deployed: these devices control axial damping (FIG. 7: Dynamic Bumper Sub, FIG. 8: Dynamic Bumper Sub (Alternate)), torsional damping (FIG. 10: Dynamic Clutch Sub), drillstring vibration, (FIG. 11: Vibrator Sub), and drillstring energy modulation (FIG. 12: Dynamic Bending Sub.) Power for all of these elements is derived from an electrical hardwire run through the internal diameter of the drillstring.
The instant device constitutes improvement over Gleitman as it is functionally autonomous, includes a relatively limited number of inexpensive sensors does not require hard wire back to a surface power source and works semi-autonomously with a lower power budget.
Nichols et al (U.S. Pat. No. 6,997,271) DRILLING STRING TORSIONAL ENERGY CONTROL ASSEMBLY AND METHOD introduce an electro-hydraulically controlled clutch assembly permitting slippage between an upper and a lower component of the drilling assembly. The device uses a plurality of hydraulically controlled pistons to provide friction against hardened cams which are attached to a cam shaft. A plurality of these devices provides for adjustable levels of torque transfer between upper and lower assembly. The instant device represents an improvement over Nichols as it allows for simultaneous torsional and axial compliance, where Nichols provides only torsional compliance.
Haughom, (U.S. Patent Application 2006/0185905) DYNAMIC DAMPER FOR USE IN A DRILL STRING proposes a device which is constructed from “an outer and inner string section and supported concentrically and interconnected through a helical threaded connection, so that relative rotation between the sections caused by torque will give an axial movement that lifts and loosens the drill bit from the bottom of the hole in critical jamming situations.” The helical sections are supported on spring means with additional hydraulic damping capability being created by narrow passages between inner and outer members.
The Haughom device offers unilateral axial damping in combination with helical adjustment at a single natural frequency. The instant device considers that bidirectional axial and torsional damping at multiple frequencies is required in order to effectively compensate for drillstring over-feed. Drillstring overfeed causes the over-torsion and severe twisting of the drillstring. The instant device provides for limiting the energy to the drill bit by simultaneously adjusting the torsional load and axial loads independently whilst maintaining the drilling process.
Additionally, the Haughom device functions by lifting the bit from the bottom of the hole, thus disrupting the drilling process; the instant invention allows the bit to remain on the bottom of the wellbore, providing for improvements in drilling efficiency. Furthermore, the instant device also considers that adjustable and adaptive damping is necessary in order to be able to accommodate a broad spectral range of harmonic vibration through an array of fluid transfer chambers and adjustable chokes or valves in the transfer passage between the appropriate chambers.
Raymond et al (U.S. Pat. No. 7,036,612) CONTROLLABLE MAGNETO RHEOLOGICAL FLUID BASED DAMPERS FOR DRILLING sought to overcome the limitations inherent in prior damping mechanisms by proposing a controllable damping apparatus for the downhole reduction of harmonic vibration. This device, which is loosely based on a traditional shock absorber format, has an adjustable element which utilizes magneto rheological fluid (“MRF”). The adjustable element incorporates restrictive valves which control magneto rheological fluid (“MRF”) which are housed within a chamber with an orifice separating two sections of the chamber. An electromagnetic coil “employed proximate the orifice” controls the flow of fluid between the two sections.
Magneto Rheological Fluids (“MRF”) are fluids which have an initial state and a second state and whose material properties are altered through the presence of a magnetic field. The first, lower viscosity state, is the natural state of the fluid, whereas the second, high-viscosity state is induced through the application of a magnetic field to the fluid. The magnetic field may be induced by application of rare-earth magnets, or, alternatively through the application of an electro-magnetic field. The magnetic field may also be permanent or temporary in nature without detriment to the characteristics of the fluid. Additionally, the field may also be configured to be a bi-state, binary operator, temporary or pulsed, thus making it almost infinitely adjustable across a range of values.
Advantageously, the “activation-time” between fluid states is relatively rapid. The Lord Corporation, manufacturers of fluids with MR properties quote activation times of 0.07 seconds. This corresponds to a frequency of approximately 14.25 Hz, placing it within the upper range of vibrations encountered in harsh drilling conditions.
Magneto Rheological materials encompass materials with both fluid and solid properties. Although MRE (“Magneto Rheological Elastomers”) are, from the material property standpoint of containment, preferable to the fluid properties which are encountered with magneto rheological fluids, energy consumption demands which are inherent in MRE deployment make it preferable to utilize MRF. From a comparative perspective, it appears that energizing an MRE takes approximately 2.5 times the power draw of energizing an MRF. Thus, the instant device may incorporate by reference MRE, but preferentially use MRF in its actuation mechanism.
The Raymond mechanism claims means for “providing frictional properties that are alterable while the drillstring is in use; and controlling the frictional properties based upon changing ambient conditions encountered by the bit. The invention preferably dampens longitudinal vibrations and preferably additionally dampens rotational vibrations. Two damping mechanisms in series may be employed.” Axial and torsional vibration damping mechanisms are configured separately in the Raymond invention [FIG. 4A/4B.], leading to a device which is substantially longer and more flexible than the one proposed in the instant invention. Further, the torsional element of the Raymond device is constrained to less than 90° of differential rotational damping prior to reaching an end-stop. The constraint is inherent in the format of the hydraulic radial damping mechanism means which utilizes MR fluids which are compressed between an internal rotor and external stator configuration means. [FIG. 3C]: the instant invention is not so constrained and may, dependent on configuration be capable of freedom of motion greater than 90° and in excess of 360° of rotation.
Additionally, the instant invention incorporating torsional damping means within a single device, presents improvements over prior art in that it is shorter, [less than one-third the physical length] less flexible and thus has a more predictable modulus of elasticity for use in bottom-hole-assembly modelling.
The Raymond device has, as its mechanical basis, spring mechanisms, which have natural frequencies and were reported as 32.39 Hz, 26.45 Hz and 12.83 Hz respectively. Despite the use of a “controllable” MR damping element, the experiments which were carried out and reported in Raymond showed that some spring configurations were less beneficial than others:
“The importance of choosing the correct spring stiffness for the shock sub is shown in FIG. 12 for a 1500 lb WOB and 180 RPM in SWG (“Sierra White Granite”). This figure compares the effect of using 32.39, 26.45 and 12.83 Hz shock subs, with comparable damping levels to a rigid system. The 12.83 Hz shock sub performs best.”
The conclusion formed in the patent documentation suggests that the 12.83 Hz shock sub may perform best with the bit size and cutter configuration selected in the undertaking the field experiments. However, the inference should not be made, nor does the patent documentation confirm that this particular frequency is particularly significant. Nor is it immediately evident that a sprung system with a lower natural frequency is ultimately more successful across a range of drilling conditions than one with a higher natural frequency.
The Raymond device incorporates a mud powered turbine generator with which to generate electrical power for the downhole device. The turbine generator adds significant additional length to the device.
As will be illustrated, the instant invention benefits from improvements in configuration over the Raymond device.
The Raymond device claims reactive responsiveness to ambient conditions encountered by the bit. The instant device claims adaptive responsiveness as in its third alternative embodiment it integrates imported data pertaining to downhole vibrational constants, surface and downhole information from a variety of sources.
Additional work in this field which focuses on the valve means utilized for the transfer of MR fluid is disclosed in Wassell et al (U.S. Pat. No. 7,219,752) SYSTEM AND METHOD FOR DAMPING VIBRATION IN A DRILLSTRING.
The instant invention claims improvement over Wassell et al in being able to create variable magnetic field intensity with which to influence the fluid properties of magneto rheological fluid elements through relative axial and torsional displacement of its internal components and without having recourse to sophisticated control mechanisms.
Completeness of the Data
The importance to adaptive devices of completeness of data is revealed by, among others, Warren and Oster “Improved ROP in Hard and Abrasive Formations” who, in a detailed discussion on bit wear, make the following observations:
“Whether or not a cutter moves backwards depends on the amplitude of the accelerations, the frequency of the accelerations and the average rotary speed. FIG. 47 shows the amplitude/frequency regions for 60 rpm and 120 rpm where backwards rotation can occur. In general for a typical frequency of 20 Hz, any accelerations over 3.5 G for 60 rpm and 6.5 G for 120 rpm result in reverse rotation. These conditions are often observed on the D(rilling) D(ynamics) S(ub) data.
The implication of this is that without, at a minimum, the amplitude, frequency and average rotary speed of a drilling assembly, active vibration damping whether at the surface of the earth or at a distal location cannot take place. Unfortunately, not all of these inputs can be measured in the downhole environment. Without information pertaining to surface conditions and more specifically to surface RPM, the downhole device may have insufficient information to be able to determine if the distal drilling environment requires adjustment or is within acceptable limits. Thus, the importance of communicating critical information to devices associated with active vibration damping is affirmed. The instant device may claim the benefit of downlinking continuous, or semi-continuous data streams from the surface of the earth to the device and improves upon prior art through the consolidation of both surface and downhole data in the distal location in its approach to the control of harmonic vibration within a single device.
Surface Downlink Capability
A downlink communications protocol is thus required. “Downlinking” refers to the ability to send data from the surface of the earth to a downhole device. Used in conjunction with industry standard “uplink” protocols, these systems are frequently referred to as “closed-loop”.
Although “closed-loop” is referred to in several prior art publications, and most recently in particular with regard to providing instructions for 3-dimensional rotary steerable systems (“3D-RSS”) its use as a element with which to reduce harmonic vibration have, largely, gone un-remarked.
Hay et al (U.S. Pat. No. 6,948,572) COMMAND METHOD FOR A ROTARY STEERABLE DEVICE, restricts the application of its downlink protocol to usage with a 3D-RSS:
“Claim 1: In a drilling system of the type comprising a rotatable drilling string, a drilling string communication system and a drilling direction control device connected with the drilling string, a method for issuing one or more commands to the drilling direction control device . . . . ”
Alternatively, Finke et al (U.S. Pat. No. 6,920,085), “DOWNLINK TELEMETRY SYSTEM” using timed fluctuations in the drilling fluid pressure, provides for instruction via pressure pulses to a downhole assembly. In this case the designated receiving tool is a “Pressure While Drilling” tool.
McLoughlin (U.S. Pat. No. 6,847,304) “APPARATUS AND METHOD FOR TRANSMITTING INFORMATION TO AND COMMUNICATING WITH A DOWNHOLE DEVICE” proposed an intermittent method for communicating between surface and a 3D-RSS device configured about a non-rotating stabilizer format and utilizing variations in the rotary speed of the drilling assembly. Principally, this method allowed for periods of reduced or null rotary speed as significant elements in the communications protocol.
All prior art downlink protocols have in some way compromised the integrity of drilling operations.
The instant device seeks to improve over prior art through utilization of a methodology for communicating information from the surface of the earth to a downhole device on a semi-continuous or continuous basis without compromising the drilling operation. This constitutes an improvement over claims made by prior art. In addition to surface parameters, the downlinked data may incorporate, data derived from measurement-while-drilling “MWD” telemetry and which may further communicate component measurements pertaining to the real-time downhole vibrational state from sensors located in other components of the BHA, to the instant device, via the surface of the earth. The information which is transmitted may be raw, processed or encoded sensor data. At the surface the uplinked information is additionally utilized in order to preferentially modify surface RPM, thus optimizing the environment for operation of the downlink protocol.
A downlink communications protocol application which fulfils these criteria without compromising drilling operations is disclosed in U.S. Pat. No. 7,540,377 to McLoughlin & Variava, ADAPTIVE APPARATUS, SYSTEM, and METHOD FOR COMMUNICATING WITH A DOWNHOLE DEVICE. This proposes a downlink protocol which uses the optimized surface drilling RPM as a baseline for a real-time adjustable communications protocol. Advantageously, the system is capable of adaptive recalibration to accommodate alterations to the baseline RPM, without compromising drilling performance. At surface minor alterations to the frequency of the baseline drilling RPM are made in accordance with pre-determined timing intervals with the objective of conveying information to a device or multiple devices located at the distal end of the drilling assembly. The downhole device is equipped with instrumentation means such that rotation can be determined in order to be able to identify alterations to rotational speed in the distal environment.
Thus a significant improvement which the instant device claims over prior art is the ability to incorporate surface and downhole data within devices located within the distal environment through closing of the communications loop between the surface of the earth and the instant downhole device. This is accomplished without detriment to the drilling process.
Additionally, the inventors believe that the partial successes of prior art and the body of information accumulated to date indicate that it is insufficient to focus on a single source of harmonic drilling problems to resolve a solution, and that an integrated closed loop and in addition, adaptive approach may be required in some circumstances.
This integrated and adaptive approach allows for continuous adjustment of the damping capabilities and characteristics of the instant device in response to changes in drilling conditions. The ability, conferred by downlink protocol, of an instrumented version of the instant device to comprehend alterations to proximal drilling harmonics is perceived as an improvement over prior art. The characteristics may be derived from a variety of sensors and instruments located either within the drilling assembly or at the surface of the earth.
Thus the versatility of the damping system and method increases, creating the ability to adapt to changing drilling conditions in real time without compromising the efficiency and effectiveness of the drilling process.